Automated method for selecting oil producing wells to subsea demulsifier injection

ABSTRACT

The present invention refers to automated method for the selection of oil producing wells that are candidates for subsea demulsifier injection, with application in mature fields after the start of water production, aiming at increasing oil and gas production and reducing the instability of the wells.

FIELD OF INVENTION

The present invention refers to an automated method for selecting oil producing wells that are candidates for subsea demulsifier injection. The application of subsea demulsifier aims, basically, to increase the gain in oil production.

DESCRIPTION OF THE STATE OF THE ART

In the offshore oil production process, it is common the formation of water-in-oil type emulsions during the simultaneous flow of oil and co-produced water from the well bottom to the platform. Increasing the load drop, due to emulsion formation, in some production scenarios, has the consequences of reducing oil production and, in some cases, destabilizing the flow (slugs), in addition to decreasing surface processing plant performance.

The formation of stable emulsions is inherent to oil production, since the main method of secondary oil recovery is the injection of water into the producing reservoirs. In addition, insofar the wells age, those with active aquifers have their emulsified water content increased over the time, making production increasingly resistant to natural flow, generating highest load drop.

An emulsion is defined as a mixture of two immiscible liquids, one of which being dispersed in the other, in the form of droplets, and remains stabilized by the action of emulsifying agents. The emulsion formed during the concomitant production of oil and saline water is of the water-in-oil (W/O) type, where water droplets are dispersed in the oil. The produced emulsion is subjected to a sequence of treatment processes on the platform to meet oil specification requirements, for commercialization, and produced water, for disposal at sea or reinjection into wells.

Rheological properties, especially viscosity, are important parameters to evaluate the properties and stability of emulsions, which is usually associated with several factors, such as volumetric fraction of the internal phase, oil viscosity, temperature, pressure, distribution and average size of water droplets dispersed in the oil, and presence of solids (clay, sulfates, paraffin crystals, among others).

Increasing the volumetric fraction of water in oil occurs, in most cases, progressively in mature production fields. Analyzes of rheological evaluation of emulsions show that emulsions with a water content of 30% present viscosity values at about 2 to 5 times higher than the viscosity of pure petroleum. Between 50% and 70% water, the increment is even greater, and can vary between 5 and 90 times. Increasing the viscosity can cause greater difficulty in the flow of the produced fluids, as it generates a significant increase in frictional load drop. In addition, it can cause flow instability, generating slugs (alternating production of liquid and gas) that demand control of the production flow and, consequently, result in loss of oil and gas production.

Increasing the load drop, due to the formation of emulsion, and the instability of the flow (slugs), have as consequences the reduction of oil production and the performance loss of the surface processing plant.

The procedure normally adopted for wells with production instability is production with the production flow control valve (choke) restricted, in order to stabilize the flow, generating an oil production below the well potential. In addition, the increase in the relative viscosity of the emulsified fluid causes an increase in the load drop by friction along the flow and, consequently, reduces the well production flow,

For the injection of subsea demulsifier, critical points were identified, such as the absence of a corporate standard for the selection of this type of product in the field and the difficulty of measuring the production gain with its use, since the application of the product favors the choke valve opening, ensuring the stabilization of the flow, the optimization of the lift gas flow, among others, considered indirect gains.

In the implementation of the subsea injection of the demulsifier, as described in OLIVEIRA, M. C. K. et al. (2019) “subsea demulsifier injection to Enhance Crude Oil Production in Offshore Brownfields—A Success Case”, OTC-29535-MS; OLIVEIRA, M. C. K. et al. (2017) “subsea demulsifier injection to Reduce Emulsion Viscosity and Enhance Crude Oil Production”, OTC-28132-MS, in many cases, there was stabilization of the flow and the consequent production increase, achieving significant gains in oil. In these reported cases in the literature, the selection processe of candidate wells for the injection of subsea demulsifier and the quantifying processe of the potential production gain were initially performed manually, for a small sample of wells.

However, there was a need to make the solution scalable to all producing wells to mitigate the problems related to the emulsion production.

Document CA3001146C discloses a method for allocating production for an oil or gas well, using statistical models that can generate decline curve analysis estimates, introduce a deterministic approach to dealing with outliers using outlier detection algorithm and a change point detection analysis algorithm to predict completion and conclusion dates, as well as potential interventions that lead to different decline curves, indicating that there is the possibility of simulations to generate a better performance in petroleum processes.

U.S. Pat. No. 9,982,535B2 discloses a system of and method for determining whether a liquid moving in an oil-bearing reservoir rock formation is water or oil. The oil-bearing rock formation includes at production well(s) and source(s) of injected water during normal oil production. A fluid pathway is identified, baseline number of passive microseismic events is established. passive microseismic events in the fluid pathway are monitored during oil production, to sense microseismic events, in which the sensed microseismic events are compared to a baseline number of passive microseismic events.

O documento ANCIÃES, C. C. C. “O Sistema SSAO separação submarine água-Óleo) comp ferramenta para a melhoria da recuperação”—Niterói, RJ: [s.n], 2015. 117f. Departamento de Engenharia Quimica e de Petróleo—Universidade Federal Fluminense, consists of an analysis of the elements responsible for the production process, characteristics and solutions used to increase the production of an oil field, focusing on the production of water and the injection process thereof. The operator is able to carry out most of the processes, such as activation of the water injection pump, start of the injection process, washing sequence, and planned shutdowns, through the use of automated sequences and process monitoring in equipment installed at the bottom of the sea. All automated sequences were verified from integrated simulations, flow dynamics and processes, indicating that there is a need for simulations for a better approach to the impasses of oil production gain.

In view of this, no document of the State of the Art discloses an automated method for the selection of producing wells for the injection of subsea demulsifier, such as this one of the present invention.

In order to solve such problems, the present invention was developed through a technological solution for the integration of the underwater injection of products with demulsifying action with an automated protocol for the selection of producing wells for which the potential for production gain is greater.

The present invention provides a method based on clear and well-defined criteria to automatically identify producer wells that are candidates for subsea demulsifier injection, via chemical injection umbilical or by gas-lift valve, and quantify the potential for production gain by injecting the demulsifier product. In other words, the method allows to verify in real time the technical and financial feasibility of the subsea demulsifier injection.

The automated method, object of the present invention, allows maximizing the production potential of maritime wells, with the objective of reducing severe slugs (stabilizing the flow) and increasing the efficiency of production flow and the associated oil gain. As an additional benefit of the invention, it is expected to reach new levels of production potential in existing systems and wells, improve the treatment of the produced water, reduce the pressure in the production header by mitigating slugs, and increasing the recovery factor of the producing field. The present invention applies to maritime producing fields after the start of water production.

The success in the implementation of this solution depends on the adequate selection of wells that meet the criteria established in the method, to identify the wells with the greatest potential for oil gain, and for the adequate selection of the chemical product, which has to be injected continuously and at the optimal dosage.

The implementation of the present invention does not require additional investments in the installation (CAPEX) and involves low operating costs (OPEX), resulting only from the acquisition of products suitable for the production scenario, being in the order of US$1.46 per barrel produced.

Thus, this invention presents technical and economic advantages to be applied in the offshore mature fields with significant production gains. The scope of the application and the constant optimization of operating conditions indicate a high potential for financial return from the application of this technological solution in mature fields.

BRIEF DESCRIPTION OF THE INVENTION

The present invention refers to an automated method for the selection of producing wells to subsea injection of products with demulsifying action (DSS), considering those with the greatest potential for oil gain and the selection of products that meet the subsea specification and present adequate performance in water-oil separation, thus aiming at increasing oil and gas production and reducing well instability.

The present invention is applicable in mature producing fields offshore.

BRIEF DESCRIPTION OF DRAWINGS

The present invention will be described in more detail below, with reference to the attached figures which, in a schematic way and not limited of the inventive scope, represent examples of its realization. In the drawings, there are:

FIG. 1 illustrates a model of the wells in the permanent flow simulator;

FIG. 2 illustrates graphs of relative viscosity of oil emulsions from wells A and B with different water contents;

FIG. 3 illustrates a load drop variation curve (F) as a function of time in the flow of the oil emulsion X with a water content of 50% and in the presence of products E, F and G;

FIG. 4 illustrates the Reynolds number profiles of the wells model A and B obtained by the steady-state flow simulator without emulsion (dashed line) and with emulsion (solid line);

FIG. 5 illustrates the operating conditions of well A with emulsion (solid squares) and without emulsion (solid circles);

FIG. 6 illustrates the screen of the automated method of selection criteria for wells with greater production gain potential.

DETAILED DESCRIPTION OF THE INVENTION

The method developed, object of the present invention, is based on the criteria for selecting wells with the greatest potential for oil gain and for the selection of products that meet the subsea specifications and present adequate performance in the water-oil separation. These criteria include the evaluation of the rheological data of the produced fluids and the flow conditions of the production scenario.

The well selection criteria considers that the greatest oil gain with the subsea demulsifier injection is observed in wells that produce stable emulsions with water contents above 30% flowing with a Reynolds number less than 105 (outside the completely turbulent region). The oil flow gain, obtained in the field and validated by the simulations, occurs due to the reduction of the friction load loss; given by the viscosity reduction when there is separation of the water and oil phases during the flow.

The automated method defined in the present invention to select candidate wells for subsea demulsifier injection comprises the following steps:

-   -   1. Evaluateing well data, such as: BS&W, free water content,         pressure profile over time to identify flow instability, oil         production flow, temperature profile, etc. The greatest         potential for oil gain will be obtained in wells that produce         stable emulsions (without free water), with high viscosity and         water content greater than 30%;     -   2. Identifying the flow regime of the well in production between         the injection point of the product and the surface installation.         This information is obtained based on the specific mass and         viscosity of the oil and emulsions, in addition to the geometric         characteristics of the production line (diameter and length).         Greater oil gain is expected if the fluid is flowing with a         Reynolds number lower than 1×10⁵; that is, outside the         completely turbulent region, at the base of the riser,     -   3. Simulating the steady flow regime in the flow simulator         MARLIM (multiphase flow and Artificial Lift Modeling) to         quantify the oil production gain with water-oil phase separation         (i.e., no emulsion) using the updated representative well model.         If the modeled fluid is not representative, collect a sample and         request the rheological evaluation of the emulsion produced in         the laboratory. The simulation is performed using mathematical         correlations that represent the fluid flow in steady state,         considering the fluid viscosity data at different temperatures;     -   4. Simulating the flow in in transient regime in the flow         simulator OLGA (Dynamic Multiphase Flow Simulator) to evaluate         the oil gain with the flow stabilization due to the phase         separation (viscosity without emulsion);     -   5. Preparing the well for the injection of the chemical         demulsifier specified for subsea injection by injection         umbilical or by gas lift valve and start the injection;     -   6. Carrying out the selection of the injected demulsifier         chemical, by bottle testing at the temperature and flow time,         between the injection point and the platform, and identify the         most appropriate dosage considering the separation performance         and the quality of the oily water. The higher the free water         content, the lower the friction loss;     -   7. Optimizing the dosage of demulsifier injected into the         surface treatment plant. The dosage can be reduced, since the         phases will arrive separately in the treatment equipment, and,         in some cases, the addition of this product may no longer be         necessary;     -   8. Monitoring the production of water during the productive life         of the well, since from the water saturation point in the oil         (BS&W >75%) it may not be necessary to continue the injection of         the subsea demulsifier.

The well selection steps (1 to 5) were automated in a web tool that reads information from the integrated production database (steps 1 and 2) and from the PI (Plant Information) System in real time, associating it with the results from the flow simulations (steps 3 and 4), it makes a checklist of the protocol requirements and, through established calculation assumptions, informs the potential for oil gain with the application of the product. From the expected flow increase, it is possible to evaluate the financial viability of the product injection, by comparing the expected additional revenue for the production gain with the injection cost.

Corrosion problems arising from the separation of saline free water in producing wells are not expected, as the metallurgy of the lines and production facilities were selected for this scenario. In transfer pipelines designed for the flow of dehydrated oil, if there is an emulsion flow and the demulsifier product is injected, it is recommended to inject a corrosion inhibitor product in the formulation.

Subsea injection of flow-enhancing products with a demulsifier function is a technically viable alternative to increase the potential for oil production from mature fields that meet the aforementioned criteria.

EXAMPLES

The following examples are presented in order to more fully illustrate the nature of the present invention and the manner of practicing it without, however, being considered as limiting its content.

Subsea demulsifier injection was started in some wells at Petrobras with the aim to improving the flow and primary processing of fluids, the classification of the water and solids content in the oil (BS&W) and the oil and grease content (TOG) in the produced water. With the perception of a gain in oil production and the stabilization of the flow in the wells with the injection of this product, an initiative was created to leverage the implementation of the subsea demulsifier injection. During this period, around 20 wells were tested, with 60% showing significant oil gains. As it was found that the production gain vaned from one well to another, in order to expand the use of demulsifier in offshore production systems, it was considered important to define an automated method with criteria for selecting candidate wells with greater potential for oil gain and for the selection of more efficient products.

To define this method, tests were initially carried out on the bench and in loop of flow to evaluate the mechanism of action and the performance of products and, then, the modeling of the flow in the simulators of steady and transient regime (MARLIM and OLGA, respectively), based on the real data of the production tests in two wells.

Example 1: Evaluation of Wells (A) and (B)

The present invention can be exemplified by evaluating the data from wells (A) and (B) that showed production gains after the subsea demulsifier injection.

Table I summarizes some field data and FIG. 1 presents the geometry of the wells evaluated in the MARLIM flow simulator.

TABLE 1 Data from wells A and B Well A B API density 17.4 18.2 BS&W 65 68 ANM depth (m) 1,553 1,545 Production duct 4,408 3,495 length (m) Liquid flow Before DSS 1,275 1,762 (Sm³/d) After DSS 2,363 2,600

The injection of demulsifier #1 was started in well A, during the test period. The test was concluded with the approval and definition of the dosage of the product for the conclusion of a supply contract. During the test, the well produced stably with full opening of the choke valve, resulting in a production gain of 300 Sm³/d of oil.

Demulsifier #2 was tested in well B in the same test period as in well A. It was found that this well was very sensitive to changes in operating conditions, becoming unstable in the event of a change in the alignment between the production trains, a drop in gas lift flow etc. The test was completed without significant production gains being observed. After a few months, the well was retested with a new demulsifier #3. This time, the well produced stably at full choke valve opening, resulting in a production gain of 180 Sm³/d of oil.

For a better understanding of the data obtained in the field tests, the following activities were carried out: rheological evaluation of the pure emulsion and in the presence of demulsifiers, evaluation of emulsion stability at temperature and flow time, flow simulations in the steady state (MARLIM simulator) and transient (OLGA simulator).

Example 2: Rheological Evaluation Gives Pure Emulsion and at the Presence of Products

The rheological evaluation aims to determine the viscosity of oil with different water contents (emulsions), under different conditions of temperature and shear rate. FIG. 2 presents the results obtained in the rheological evaluation of the emulsions as a function of temperature. As can be seen, the higher the emulsified water content, the higher the emulsion viscosity.

Example 3: Stability Evaluation of Emulsions at the Flow Temperature

The load drop of an emulsion with a water content of 50% was evaluated in a flow loop in the presence of three flow improving products with demulsifying action. For this test, a 21.833 m long coil manufactured with OD ¼″×0.049″ tube (3.861 mm internal diameter) was used, a thermostatic bath adjusted to a temperature of 50° C., a positive displacement pump (maximum flow of 7.2 L/h), and a data acquisition system. Due to the high viscosity of the emulsion, the flow regime achieved was laminar.

To perform this test, the emulsion is placed in the tank with mechanical agitation, under the defined temperature condition. The flow starts with monitoring of the pressure profile until the steady state condition has been reached, maintaining the flow with recirculation to the cargo tank. After stabilization of the emulsion flow, the chemical to be tested is dosed directly into the tank with agitation over the emulsion. The flow parameters through the loop are kept unchanged and the test is monitored until the new pressure curves stabilization condition is reached.

FIG. 3 shows the load drop variation curves in the flow of the emulsion prepared with X oil with a water content of 50% in the loop before and after the addition of demulsifying products E, F and G. By analyzing the curves, it is observed that product B promoted a small reduction in load drop (around 20%), while in the presence of product F, the reduction load drop is gradual, reaching 85%. Product G promoted the immediate separation of water, providing the maximum reduction in load drop. These results are in agreement with others obtained previously in the rheological and stability evaluation, where a viscosity reduction of 45%, 67% and 78% was observed with products B, F and G, respectively, and also the destabilization of the emulsion in the presence of the products F and G. Therefore, the results indicate that the load drop will be smaller when there is an effective separation of the phases; that is, the higher the free water content. Products that present higher performance in the separation of water and oil phases, under flow conditions, promote greater reduction in load drop. Suitable product selection is critical to the success of this technological solution.

Then, based on the values obtained in the rheological evaluation, flow simulations were performed in order to reproduce the field data before and after the demulsifier injection. For that, the fluid models with and without emulsion were considered the same. In the model without emulsion, all the water is separated from the oil (free water), demulsified. In practice, it is known that the demulsifier can act partially, destabilizing only a fraction of the water present in the W/O emulsion. The time for the product to act was not considered in the model without emulsion.

Evaluating the flow parameters, it is known that when the Reynolds number increases, the flow regime transitions from laminar to turbulent, with a reduction in the friction factor and, consequently, in the load loss by friction. Keeping the other variables constant, the reduction of the friction factor increases the oil production flow by the relationship described in equation 1.

$\begin{matrix} {Q = \left( {\frac{1}{f} \cdot \frac{\pi^{2}D^{5}}{8\rho} \cdot \frac{\Delta P}{L}} \right)^{\frac{1}{2}}} & (1) \end{matrix}$

where: Q—flow, D—diameter, P—pressure, f—friction factor, p—fluid density, and L—line length.

The simple evaluation of the Reynolds profile of the fluid flow in the field can indicate regions of laminar regime and, therefore, wells with potential to gain oil production through the injection of demulsifier. The same can be said for turbulent flows with a Reynolds number below 10⁵, for example, as can be seen in the Moody Diagram (not shown here).

By the analysis of the Moody Diagram, it is verified that the increase of the Reynolds number, in a section of the flow located in the stretch of the riser, favors the reduction of the friction factor and the transition from the laminar to the turbulent regime. This section was selected because it has low Reynolds, where the reduction of viscosity exerts greater influence on the reduction of the friction factor. The

${Re}_{L} = \frac{\rho_{L}v_{L}F}{\mu_{L}}$

dimensionless Reynolds number (equation 2) shows the relationship with the viscosity of the fluid, where the reduction of this parameter favors the transition of the flow regime. For this assessment to be possible, it is essential to use a representative fluid model, as indicated in the study of wells A and B.

-   -   (2)         Where, pL is the specific mass of the liquid; vL is the average         velocity of the liquid; μL is the effective viscosity of the         liquid; D is the inner diameter of the pipe.

After alterations and adjustments in the simulation models, it was observed that the correct representation of the viscosity and flow values implies the calculation of the correct Reynolds number, which is one of the pillars of the method for identifying candidate wells for subsea demulsifier injection. Furthermore, small changes in boundary conditions (such as reservoir pressure, surface pressure, BS&W, or gas-liquid ratio—RGL) of an unrepresentative model can lead to high prediction errors, as the model would properly represent only one operation point of the well.

The simulation of the steady flow regime indicates the oil production gain by the phase separation, while the transient flow simulation reproduces the production conditions before and after the injection of the product, especially with regard to production stability and opening of the choke valve. Taking the modified well A model as a reference, FIG. 4 shows the Reynolds profile with and without the emulsion viscosity calculation option enabled.

The original model for well B provided a liquid flow rate of 2,358 Sm³/d and contemplated the calculation of the relative viscosity of the emulsion according to the Woelflin model (weak emulsion). In the modified model; with the emulsion calculation disabled, the liquid flow increased to 2944 Sm³/d, indicating a gain of 586 Sm³Id of liquid, 270 Sm³/d of oil.

The gains associated with the stabilization of production and consequent opening of the choke valve were also evaluated. In the transient analysis the boundary conditions replicated the production test conditions before and after the demulsifier injection. From the simulated results, it is concluded that well A has an unstable production zone, shown in FIG. 5 . Therein, the numbered arrows indicate the following operations:

-   -   1. Demulsifier injection with increased production due to         reduced fluid viscosity; still with the choke valve restricted;     -   2. Gradual opening of the choke valve, facilitated by flow         stability;     -   3. Interruption in the demulsifier injection and consequent         reduction in production flow due to the increase in fluid         viscosity, with the flow remaining stable.

Example 4: Flow Simulations at the Steady (Simulator ARLIN) and Transient (Simulator OLGA) Regime

In the simulation of the production test before the demulsifier injection, the model relies on the calculation of the emulsion viscosity and with a higher arrival pressure on the platform given by the partial opening of the choke valve. As mentioned; the well A has an unstable production zone, so the injection of demulsifier in this well promotes two beneficial effects: the reduction of fluid viscosity and the stabilization of the flow, allowing greater opening of the choke valve. Such factors justify the gain in oil production verified in the field.

The transient flow simulation proved to be a useful tool in the evaluation of production gains due to the demulsifier injection, as it is capable of reproducing the production gain by the combined effect of viscosity reduction (lower load loss by friction) and reduction of inlet pressure (opening the choke valve by stabilizing the flow).

In the analysis of well B, it can be seen that the injection of demulsifier promotes the transition from the laminar to the turbulent flow, which in turn implies a reduction in the friction factor and oil gain. The transient simulation of well B provided evidence that the breakage of the emulsion would stabilize the flow, allowing the opening of the production valve choke, and would promote a production gain of around 180 Sm³/d of oil. However, such estimates did not materialize during the injection of demulsifier #2, from which it can be concluded that the product was not able to promote the total breakdown of the emulsion. On the other hand, demulsifier #3, injected later, confirmed the aforementioned expectations, indicating the good performance of the product and the effectiveness of the transient simulation in the evaluation of production gains associated with the demulsifier injection. Also, the study highlighted the importance of the stage of selecting an appropriate chemical product from tests with samples of oil from the well and the analysis in the flow conditions. Based on these results, a criterion was created for the selection of more efficient products.

For both wells studied, the reduction in the viscosity of the liquid, resulting from the separation of the water and oil phases, promoted the transition from laminar to turbulent flow, significantly reducing the friction factor and, consequently, the load loss by friction, increasing the oil gain. Thus, it is concluded that the identification of the laminar regime in the flow of fluids indicates a potential for production gain. More broadly, it can be said that there is greater potential for gain in cases where the average Reynolds number in the subsea pipelines in the emulsion flow is less than 10⁵ (outside the completely turbulent region). The flow simulation does not include issues related to the chemical performance in water-oil separation. Therefore, once the wells have been selected, the product selection step must be taken.

Regarding the tests carried out in the laboratory, it was observed that:

-   -   The performance evaluation of the products must be carried out         in the oil of the candidate well, due to the characteristic         specificity of this type of formulation;     -   The products promote changes in the size distribution of water         droplets dispersed in the oil and, depending on the dosage,         change the phase separation kinetics;     -   The greatest reduction in viscosity occurs when the saline water         is completely separated from the oil phase, that is, flowed as a         free water;     -   The tests in flow loop confirmed that the higher the free water         content, the lower the load drop in the flow;     -   Subsea injection demulsifiers must show separation efficiency at         lower temperatures than surface demulsifiers, but on the other         hand, may have slower separation kinetics (between 30-40         minutes);     -   Field product selection criteria should be based on water-oil         separation performance at runoff temperature and time.

Therefore, the following advantages of total water separation during flow were identified: reduction of load loss, stabilization of the flow pattern, anticipation of the water-oil separation process, and reduction of consumption of demulsifying chemicals in surface installations.

Based on the results obtained, a selection criterion for products with the demulsifying function for underwater injection was defined, which must meet the following steps:

-   -   1. Collecting the produced emulsion sample;     -   2. Determining the initial water content (BS&W) of the collected         sample;     -   3. Performing the emulsion stability test at the point of         injection and arrival temperatures on the platform, for 30 min         at different dosages;     -   4. Consolidating the results of the water content separated as a         function of the product concentration in tables or graphs;     -   5. Evaluating the quality of the water separated by the oil and         grease content (TOG);     -   6. Evaluating the compatibility of the subsea demulsifier with         the product injected on the surface;     -   7. Evaluating the stability of the subsea demulsifier product         under the conditions defined in the technical specification of         the chemical products subsea injection.

It is important to emphasize that the results presented demonstrated the feasibility of developing a method that allows the identification of candidate oil producing wells for the injection of subsea demulsifier. Without an automated method, presented in this invention, the application depends on human intervention, which in turn demands time and specialized work. FIG. 6 shows the screen of the automated method of selection criteria for wells with greater production gain potential.

It should be noted that, although the present invention has been described in relation to the attached drawings, it may undergo modifications and adaptations by technicians versed in the subject, depending on the specific situation, but provided that it is within the inventive scope defined herein. 

1- AUTOMATED METHOD FOR SELECTING OIL PRODUCING WELLS TO SUBSEA DEMULSIFIER INJECTION, characterized by comprising the following steps:
 1. Evaluating the well production data;
 2. Identifying the flow regime of the well in production between the injection point of the product and the surface;
 3. Simulating the steady flow regime to quantify the oil production gain with the separation of the water-oil phases (without emulsion), using the updated representative model of the wed;
 4. Simulating flow in a transient regime to evaluate the gain in flow stabilization with the phase separation (viscosity without emulsion);
 5. Preparing the well for the injection of the demulsifying chemical specified for subsea injection and start the injection;
 6. Performing the selection of the injected demulsifier chemical product and identifying the most appropriate dosage;
 7. Optimizing surface demulsifier injection;
 8. Monitoring the production and quality of water during the productive life of the well. 2- AUTOMATED METHOD FOR SELECTING OIL PRODUCING WELLS TO SUBSEA DEMULSIFIER INJECTION, according to claim 1, characterized by the steps (1 to 5) of selection of the wells being automated in a tool web which reads information from the integrated production database (steps 1 and 2) and from the PI in real time, associates it with the simulation results (step 3 and 4), makes a check first of the method requirements and, through established calculation assumptions, informs the potential for oil gain with the application of the product. 3- AUTOMATED METHOD FOR SELECTING OIL PRODUCING WELLS TO SUBSEA DEMULSIFIER INJECTION, according to claim 1, characterized in thar the wells that present the greatest potential for oil gain are those that produce stable emulsions (without free water), with high viscosity and with water content greater than 30%. 4- AUTOMATED METHOD FOR SELECTING OIL PRODUCING WELLS TO SUBSEA DEMULSIFIER INJECTION, according to claim 1, characterized in that the well flow regime has a Reynolds number lower than 1×10⁵ at the base of the riser. 5- AUTOMATED METHOD FOR SELECTING OIL PRODUCING WELLS TO SUBSEA DEMULSIFIER INJECTION, according to claim 1, characterized in that the selection of the demulsifier chemical product for underwater injection is carried out by bottle test at temperature and flow time, between the injection point and the platform. 